1. Field of the Invention
The present invention relates generally to a method for the prevention of damage to oil and gas wells, and, more specifically, to the prevention of damage to the well casing from critical annular pressure buildup.
2. Description of the Prior Art
The physics of annular pressure buildup (APB) and associated loads exerted on well casing and tubing strings have been experienced since the first multi-string completions. APB has drawn the focus of drilling and completion engineers in recent years. In modern well completions, all of the factors contributing to APB have been pushed to the extreme, especially in deep water wells.
APB can be best understood with reference to a subsea wellhead installation. In oil and gas wells it is not uncommon that a section of formation must be isolated from the rest of the well. This is typically achieved by bringing the top of the cement column from the subsequent string up inside the annulus above the previous casing shoe. While this isolates the formation, bringing the cement up inside the casing shoe effectively blocks the safety valve provided by nature's fracture gradient. Instead of leaking off at the shoe, any pressure buildup will be exerted on the casing, unless it can be bled off at the surface. Most land wells and many offshore platform wells are equipped with wellheads that provide access to every casing annulus and an observed pressure increase can be quickly bled off. Unfortunately, most subsea wellhead installations do not have access to each casing annulus and often a sealed annulus is created. Because the annulus is sealed, the internal pressure can increase significantly in reaction to an increase in wellbore temperature.
Most casing strings and displaced fluids are installed at near-static temperatures. On the sea floor the temperature is around 34° F. The production fluids are drawn from “hot” formations that dissipate and heat the displaced fluids as the production fluid is drawn towards the surface. When the displaced fluid is heated, it expands and a substantial pressure increase may result. This condition is commonly present in all producing wells, but is most evident in deep water wells. Deep water wells are likely to be vulnerable to APB because of the cold temperature of the displaced fluid, in contrast to elevated temperature of the production fluid during production. Also, subsea wellheads do not provide access to all the annulus and any pressure increase in a sealed annulus cannot be bled off. Sometimes the pressure can become so great as to collapse the inner string or even rupture the outer string, thereby destroying the well.
One previous solution to the problem of APB was to take a joint in the outer string casing and mill a section off so as to create a relatively thin wall. However, it was very difficult to determine the pressure at which the milled wall would fail or burst. This could create a situation in which an overly weakened wall would burst when the well was being pressure tested. In other cases, the milled wall could be too strong, causing the inner string to collapse before the outer string bursts.
In U.S. Pat. No. 6,675,898, assigned to the assignee of the present invention, an alternative design was shown which comprised a casing coupling modified to include at least one receptacle for housing a modular “burst disk” assembly. The burst disk assembly was designed to fail at a predetermined pressure and was compensated for temperature. The disk was designed to intentionally fail when the trapped annular pressure threatened the integrity of either the inner or outer casing. The design also allowed for the burst disk assembly to be installed on location or before pipe shipment.
Despite the advantages offered by the improved burst disk design, a need continues to exist for further improvements in automatic pressure relief systems of the type under consideration.